Hybrid parallel / serial process for carbon dioxide capture from combustion exhaust gas using a sweep-based membrane separation step

ABSTRACT

A gas separation process for treating an exhaust gas stream from a combustion processes. The invention involves routing a first portion of the exhaust stream to a carbon dioxide capture step, and flowing a second portion of the exhaust stream and at least a portion of an off-gas stream from the carbon dioxide capture step across the feed side of a membrane, while flowing a sweep gas stream, usually air, across the permeate side, and then passing the resulting permeate sweep stream back to the combustor.

The present application is a continuation-in-part and claims the benefit of U.S. patent application Ser. No. 13/548,827, filed Jul. 13, 2012; which is a continuation-in-part and claims the benefit of both (1) U.S. application Ser. No 13/115,726, filed May 25, 2011, which issued Jul. 17, 2012, as U.S. Pat. No. 8,220,248; which is a continuation-in-part and claims the benefit of U.S. application Ser. No 13/122,136, filed Mar. 31, 2011, which issued May 15, 2012. as U.S. Pat. No 8,177,885; which is a national stage application of, and claims the benefit of, PCT Application No. PCT/US10/02480, filed Sep. 13, 2010; and (2) U.S. patent application Ser. No. 13/122,136, filed Mar. 31, 2011, which issued May 15, 2012, as U.S. Pat. No. 8,177,885; which is a national stave application of, and claims the benefit of, PCT Application No. PCT/US10/02480, filed Sep. 13, 2010; the entire contents of all of which applications are hereby incorporated by reference.

FIELD OF THE INVENTION

The invention relates to membrane-based gas separation processes, and specifically to processes using a sweep gas on the permeate side of the membrane to remove carbon dioxide from combustion gases.

BACKGROUND OF THE INVENTION

Many combustion processes produce flue gases contaminated with carbon dioxide that contribute to global warming and environmental damage.

Such gas streams are difficult to treat in ways that are both technically and economically practical, and there remains a need for better treatment techniques.

Gas separation by means of membranes is a well-established technology. In an industrial setting, a total pressure difference is usually applied between the feed and permeate sides, typically by compressing the feed stream or maintaining the permeate side of the membrane under partial vacuum.

It is known in the literature that a driving force for transmembrane permeation may be supplied by passing a sweep gas across the permeate side of the membranes, thereby lowering the partial pressure of a desired permeant on that side to a level below its partial pressure on the feed side. In this case, the total pressure on both sides of the membrane may be the same, the total pressure on the permeate side may be higher than on the feed side, or there may be additional driving force provided by keeping the total feed pressure higher than the total permeate pressure.

Using a sweep gas has most commonly been proposed in connection with air separation to make nitrogen or oxygen-enriched air, or with dehydration. Examples of patents that teach the use of a sweep gas on the permeate side to facilitate air separation include U.S. Pat. Nos. 5,240,471; 5,500,036; and 6,478,852. Examples of patents that teach the use of a sweep gas in a dehydration process include U.S. Pat. Nos. 4,931,070; 4,981,498; and 5,641,337.

Configuring the flow path within the membrane module so that the feed gas and sweep stream flow, as far as possible, countercurrent to each other is also known, and taught, for example in U.S. Pat. Nos. 5,681,433 and 5,843,209.

SUMMARY OF THE INVENTION

The invention is a process involving membrane-based gas separation, for controlling carbon dioxide emissions from combustion processes, and combustion processes in which carbon dioxide emissions are so controlled.

Combustion exhaust streams or off-gases are typically referred to as flue gas, and arise in large quantities from ovens, furnaces, and boilers in all sectors of industry. In particular, power plants generate enormous amounts of flue gas. A modestly sized 100 megawatt coal-based power plant may produce over 300 MMscfd of flue gas.

The major components of combustion exhaust gases are normally nitrogen, carbon dioxide, and water vapor. Other components that may be present, typically only in small amounts, include oxygen, hydrogen, SO_(x), NO_(x), and unburnt hydrocarbons. The carbon dioxide concentration in the flue gas is generally up to about 20 vol %.

In addition to gaseous components, combustion flue gas contains suspended particulate matter in the form of fly ash and soot. This material is usually removed by several stages of filtration before the gas is sent to the stack. It is assumed herein that the flue gas has already been treated in this way, if desired, prior to carrying out the processes of the invention.

The process of the invention involves treating the exhaust or flue gas to remove carbon dioxide. In preferred embodiments, the carbon dioxide level of the exhaust gas is reduced to as low as 5 vol % or less; preferably, to 3 vol % or 2 vol %; and often, to 1 vol % or less. Discharge of such a stream is much less damaging to the environment than discharge of the untreated exhaust.

The combustion process from which the exhaust is drawn may be of any type. The fuel may be a fossil fuel, such as coal, oil or natural gas, or maybe from any other source, such as landfill gas, biomass, or other combustible waste. The fuel may be combusted by mixing with air, oxygen-enriched air or pure oxygen.

In a previous patent, U.S. Pat. No. 7,964,020 (“the '020 patent”), issued Jun. 21, 2011, we described a “serial” flue gas treatment process in which an exhaust stream from a combustion process is first sent to a carbon dioxide capture step, which may utilize any separation technology suitable for recovering carbon dioxide from a stream of the exhaust gas concentration. The off-gas stream from the capture step still contains carbon dioxide, but normally at a lower concentration than the raw exhaust stream. Typically, this concentration is up to about 10 vol % carbon dioxide. This off-gas stream is then sent to a sweep-based membrane separation step. The sweep stream is typically air, oxygen-enriched air, or oxygen. The carbon dioxide and oxygen-enriched combined permeate/sweep stream from the membrane separation step is returned to the combustion process.

In a subsequent patent, U.S. Pat. No, 8,025,715 (“the '715 patent”), issued Sep. 27, 2011, we described a flue gas treatment process in which a carbon dioxide capture step and a sweep-based membrane separation step are performed in parallel (rather than serially, as described in the '020 patent). That is, one portion of the exhaust stream from the combustion process is routed to a carbon dioxide capture step, and the other portion is routed to a sweep-based membrane separation step.

We have now discovered that a hybrid parallel/serial flue gas treatment process provides unexpected advantages over either the serial process described in the '020 patent or the parallel process described in the '715 patent.

In the simple serial design described in the '020 patent, the total exhaust stream to be treated is sent through the first carbon dioxide separation step, and a portion of the carbon dioxide content is removed. The partially treated gas is then sent to a sweep-based membrane separation step where the remaining carbon dioxide content of the gas is removed.

In the simple parallel design described in the '715 patent, only a portion of the exhaust gas is sent to the carbon dioxide separation step, but essentially all of the carbon dioxide content of the gas is removed to produce dischargeable flue gas. In comparison to the serial ease, a smaller volume of gas must be treated (which reduces cost), but more complete removal of carbon dioxide from the gas is required (which increased cost).

The choice between the serial design (as described in the '020 patent) or parallel design (as described in the '715 patent) will depend on the nature of the carbon dioxide separation processes. Some cryogenic processes, for example, will likely be favored by the serial design because achieving very high carbon dioxide removal required high pressure and low temperatures. Some absorption or adsorption processes that use very strong reactive reagents will be favored by the parallel design, because they can achieve complete removal of carbon dioxide from the flue gas (which reduces cost compared to the simple serial case).

In the hybrid parallel I serial design of the present invention, only a portion of the exhaust gas is sent to the carbon dioxide separation step, but only a portion of the carbon dioxide content of the gas is removed (which reduces cost compared to the simple parallel case). A portion of the treated exhaust gas is then sent back to be remixed with the other portion of the exhaust gas to be treated by the sweep-based membrane separation step.

In the present embodiment, the carbon dioxide capture step and the sweep-based membrane separation step are conducted in parallel, with a first portion of the combustion exhaust stream sent to a carbon dioxide capture step, and a second portion of the exhaust stream sent to a sweep-based membrane separation step. The difference between the process of the present invention and the serial and parallel processes taught, respectively, in the '020 and '715 patents is that, in the present invention, at least a portion of an off-gas stream from the carbon dioxide capture step and the second portion of the exhaust stream are combined and sent as a feed stream to the membrane separation step.

Accordingly, a basic embodiment of the present invention includes the following steps:

(a) performing a combustion process by combusting a mixture of a fuel and air, oxygen-enriched air, or oxygen, thereby creating an exhaust stream comprising carbon dioxide and nitrogen;

(b) performing a carbon dioxide capture step to remove a portion of carbon dioxide in concentrated form from a first portion of the exhaust stream, thereby creating an off-gas stream from the capture step that is less concentrated in carbon dioxide than the exhaust stream;

(c) providing a membrane having a feed side and a permeate side, and being selectively permeable to carbon dioxide over nitrogen and to carbon dioxide over oxygen;

(d) passing a second portion of the exhaust stream and at least a portion of the capture step off-gas stream across the feed side;

(e) passing air, oxygen-enriched air, or oxygen as a sweep stream across the permeate side;

(f) withdrawing from the feed side a carbon-dioxide depleted vent stream;

(g) withdrawing from the permeate side a permeate stream comprising oxygen and carbon dioxide;

(h) passing the permeate stream to step (a) as at least part of the air, oxygen-enriched air, or oxygen used in step (a).

In accordance with step (d), a second portion of the exhaust stream and at least a portion of the, off-gas stream from the capture step are sent for treatment in a sweep-based membrane separation unit. The at least a portion of the capture step off-gas stream that is sent for treatment in the membrane unit typically comprises between about 3 vol % to about, 20 vol % carbon dioxide.

The process is particularly useful in applications that are energy-sensitive, as is almost always the ease when the very large exhaust streams from power plants and the like are to be processed. Typically, the exhaust stream emanates from a gas turbine, steam turbine, or boiler. An objective of the invention is to substantially increase the concentration of carbon dioxide in the exhaust stream from the turbine or boiler, so that the portion of the exhaust stream that is sent to the carbon dioxide capture step can itself be concentrated and captured more efficiently than would otherwise be possible. This is achieved by returning the carbon dioxide-enriched permeate stream from the sweep-based membrane separation step to the combustor. The exhaust stream from the combustor preferably comprises at least 10 vol % CO₂; more preferably, at least 15 vol % CO₂; most preferably, at least 20 vol % CO₂; and may in some cases contain as much, as 25 vol % CO₂.

If the gas needs to be transported to reach the equipment that carries out the carbon dioxide capture step, such as an amine plant, transportation of the carbon dioxide enriched exhaust gas is far simpler and less costly than transporting low concentration raw flue gas from a conventional power plant. Typically, the amount of gas that must be pipelined or otherwise transported to the carbon dioxide capture plant is reduced several fold, such as to 50%, 30%, or even 25% or less of the amount that would need to be sent if the membrane separation step were absent. This is a significant benefit of the invention,

The first portion of the exhaust stream that is sent to the carbon dioxide capture step preferably comprises between about 10 vol % and about 75 vol %; more preferably, between about 20 vol % and 65 vol %; and, most preferably, between about 40 vol % and about 60 vol % of the total exhaust stream. This can also be expressed as a split ratio, where the ratio defines the relative proportions of the flue gas sent to the carbon dioxide capture step and the membrane separation step. In general, we prefer to operate with a split ratio between about 1:5 and about 2:1.

The carbon dioxide capture step preferably comprises at least one process selected from the group consisting of absorption, adsorption, liquefaction, and membrane separation. Typically, the capture step is an absorbent-based step, which may be either a chemical or a physical absorption process. Most typically, the carbon dioxide capture step is performed using amine scrubbing. This capture step removes a portion of the carbon dioxide from the emissions stream, and preferably provides it in the form of a concentrated stream, such as greater than 60 vol %, 70 vol %, or 80 vol % carbon dioxide, and most preferably as a supercritical fluid or liquid high purity product. The concentrated carbon dioxide product stream may be sent for sequestration, or for any other use.

The second portion of the exhaust stream and at least a portion of the capture step off-gas stream are combined and sent as a feed stream to a sweep-based membrane separation step. The sweep-based membrane separation unit contains membranes that are selectively permeable to carbon dioxide over nitrogen and to carbon dioxide over oxygen. It is preferred that the membrane provide a carbon dioxide permeance of at least about 300 gpu; more preferably, at least about 500 gpu; and, most preferably, at least about 1,000 gpu under the operating conditions of the process. A carbon dioxide/nitrogen selectivity of at least about 10 or more and, preferably, 20, under the operating conditions of the process is also desirable.

The sweep-based membrane separation step maybe carried out using one or more individual membrane modules. Any module capable of operating under permeate sweep conditions may be used. Preferably, the modules take the form of hollow-fiber modules, plate-and-frame modules, or spiral-wound modules. All three module types are known, and their configuration and operation in sweep, including counter-flow sweep modes, is described in the literature.

The process may use one membrane module, but in many cases, the separation will use multiple membrane modules arranged in series and/or parallel flow arrangements as is well known in the art. Any number of membrane modules may be used.

Oftentimes, the second portion of the exhaust gas stream and the capture step off-gas may be mixed directly before the sweep-based membrane separation step. However, these streams will normally have different carbon dioxide concentrations, so mixing losses will decrease the potential efficacy of the process. In some eases, the more concentrated exhaust gas stream will be sent to a first sweep-based membrane separation step to reduce the carbon dioxide concentration of the stream to a level closer to that of the carbon dioxide capture step off-gas. These streams can then be mixed and the remaining carbon dioxide reduced to an appropriate level in a final sweep operation.

Although the combined feed stream may be sent to the membrane unit without compression, the process may be augmented by operating the membrane unit with higher total pressure on the feed side than on the permeate side, thereby increasing the transmembrane driving force for permeation. For example, slight compression to a pressure from between about 1.1 bar up to about 5 bar, such as 2 bar, is preferred.

The residue stream at the end of the process is reduced in carbon dioxide content to less than about 5 vol %; more preferably, to less than 3 vol % or 2 vol %; and, often to 1 vol % or less. This stream is typically, although not necessarily, discharged to the environment. The reduction of the carbon dioxide content to 20%, 10%, or less of the content of the raw exhaust gas greatly reduces the environmental impact of discharging this stream.

The combined feed stream flows across the feed side of the membranes, and a sweep gas of air, oxygen-enriched air, or oxygen flows across the permeate side, to provide or augment the driving force for transmembrane permeation. It is preferred that the feed gas flow direction across the membrane on the feed side and the sweep gas flow direction across the membrane on the permeate side are substantially countercurrent to each other. In the alternative, the relative flow directions may be substantially crosscurrent, or less preferred, cocurrent.

The sweep stream picks up the preferentially permeating carbon dioxide. The sweep/permeate stream is then withdrawn from the membrane unit and is returned to the combustor to form at least part of the air, oxygen-enriched air, or oxygen feed to the combustion step. By using the oxygen-containing stream destined for the combustor as sweep gas, the membrane separation step is carried out in a very efficient manner, without introducing any additional unwanted components into the combustion zone. In addition, circulation of the sweep/permeate stream to the combustion step is very advantageous, as it helps to build up the carbon dioxide concentration that passes to the carbon dioxide capture step, facilitating good carbon dioxide removal in this step.

A major objective of the invention is to minimize the amount of CO, in the vent stream, which is often released directly to the environment. As such, the vent stream preferably comprises less than 5 vol % CO₂; more preferably, less than 4 vol % or 3 vol % CO₂; and often, 1 vol % or less CO₂.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic drawing of a basic flow scheme for a “serial” carbon dioxide capture/sweep-based membrane separation flue gas treatment process, as described in the '020 patent.

FIG. 2 is a schematic drawing of a flow scheme for a serial flue gas treatment process in which a membrane separation step is used in the carbon dioxide capture step, as described in the '020 patent.

FIG. 3 is a schematic drawing of a flow scheme for a serial flue gas treatment process that utilizes several membrane separation steps, as described in the '020 patent,

FIG. 4 is a schematic drawing of a flow scheme for a serial process for treatment of flue gas from a power plant or the like, as described in the '020 patent.

FIG. 5 is a schematic drawing of a basic flow scheme for a “parallel” carbon dioxide capture/sweep-based membrane separation flue gas treatment process, as described in the '715 patent.

FIG. 6 is a schematic drawing of a flow scheme for a parallel flue gas treatment process, in which the portion of the exhaust stream being routed to the sweep-based membrane separation step is passed through a compressor prior to being sent to the membrane separation step, as described in the '715 patent.

FIG. 7 is a schematic drawing of a flow scheme for a parallel flue gas treatment process, in which the carbon dioxide capture step comprises two membrane-based capture steps, as described in the '715 patent.

FIG. 8 is a schematic drawing of a flow scheme for a combustion process that does not include a sweep-based membrane separation step (not in accordance with the invention).

FIG. 9 is a schematic drawing of a basic flow scheme for a flue gas treatment process in accordance with the present invention, in which at least a portion of an off-gas stream from the carbon dioxide capture step is routed as part of a feed stream to a sweep-based membrane separation step.

FIG. 10 is a schematic drawing of a flow scheme for a steam turbine process that includes an amine absorption step, but no sweep-based membrane separation step (not in accordance with the invention).

FIG. 11 is a schematic drawing of a flow scheme for a steam turbine process in accordance with the present invention, in which a first portion of the combustion exhaust gas is routed to an amine absorption step, and at least a portion of an off-gas stream from the amine absorption step is routed as part of a feed stream to a sweep-based membrane separation step.

FIG. 12 is a schematic drawing of a flow scheme for a coal combustion process in accordance with the present invention, in which a first portion of the combustion exhaust gas is routed to a membrane-based carbon dioxide capture step, and a second portion of the exhaust gas is routed as a feed stream to two sequential sweep-based membrane separation steps.

DETAILED DESCRIPTION OF THE INVENTION

Gas percentages given herein are by volume unless stated otherwise.

Pressures as given herein are in bar absolute unless stated otherwise.

The terms exhaust gas, off-gas, flue gas, and emissions stream are used interchangeably herein.

The invention is a process for controlling carbon dioxide emissions from combustion processes by membrane-based gas separation and combustion processes including such gas separation.

A simple flow scheme for a basic embodiment of the invention described in the '020 patent is shown in FIG. 1. Referring to this figure, fuel stream 12, and air, oxygen-enriched air or oxygen stream 23, are introduced into a combustion step or zone, 11. Stream 23 is made up of sweep stream, 22, discussed below, and additional air or oxygen supply, stream 13.

Combustion exhaust stream, 14, typically containing 10-20 vol % carbon dioxide, is withdrawn. This stream usually contains at least carbon dioxide, water vapor and nitrogen, as well as the other components mentioned in the Summary section above.

The stream is sent, at least in part, to carbon dioxide capture step, 15. This step may be carried out using any technology or combination of technologies that can create a concentrated carbon dioxide stream from the exhaust stream.

The capture step yields a concentrated carbon dioxide product stream, 16, preferably containing greater than 60, 70, or 80 vol % carbon dioxide or more This stream may be in the gas or liquid phase, and may comprise purified liquid carbon dioxide, for example. The concentrated stream may be sent for sequestration, or used or disposed of in any other appropriate way.

The off-gas stream, 17, from the capture step still contains carbon dioxide, at a lower concentration than the raw exhaust stream. Typically, but not necessarily, this concentration is up to about 10 vol % carbon dioxide for coal-fired boilers, lower for gas-fired boilers. The off-gas stream is sent for treatment in membrane separation step or unit, 18. The unit contains membranes, 19, that are selectively permeable to carbon dioxide over nitrogen and to carbon dioxide over oxygen.

The off-gas flows across the feed side of the membranes; a sweep gas of air, oxygen-enriched air or oxygen, stream 21, flows across the permeate side.

The sweep stream picks up the preferentially permeating carbon dioxide, and the resulting permeate stream, 22, is withdrawn from the membrane unit and is combined with stream 13 to form the air or oxygen feed, 23, to the combustor.

In the alternative, stream 13 may be omitted and the entirety of the oxygen-containing feed to the combustor may be provided by the sweep stream.

The residue stream, 20, is reduced in carbon dioxide content to less than about 5 vol % , more preferably to less than 3 vol % and most preferably to less than 2 vol %. Typically, this stream is discharged to the environment.

One of the additional benefits of using the combustion air or oxygen supply as the permeate sweep is that the permeating carbon dioxide removed into the sweep gas is recycled to the combustion chamber. This increases the carbon dioxide concentration in the exhaust gas leaving the combustor, facilitating the downstream capture of carbon dioxide.

For example, conventional combustion of coal with air usually produces an off-gas containing 10-12% carbon dioxide, whereas returning carbon dioxide to the combustion chamber in accordance with the teachings herein can increase the off-gas concentration to about 15 or 20 vol %.

From FIG. 1, it may be seen that the process of the invention incorporates three unit operations: a combustion step, a carbon dioxide capture step and a final membrane separation step, in that order.

The combustion step may be carried out in any way limited only in that it results in an off-gas, exhaust gas or flue gas containing carbon dioxide. Such combustion processes occur throughout industrialized society. Representative processes include those in which the combustion step is used to provide heat for an oven or furnace, such as a blast furnace or rotary kiln, for example, a lime or cement kiln. Other important processes are those in which the combustion step is used to generate steam to operate a turbine or other equipment to perform mechanical work or generate electric power. In yet other processes, the combustion gases themselves are used as a source of power to drive a turbine or the like, and may be treated before or after they have been used in the turbine. Further examples of combustion processes are those used to supply heat for refinery operations, such as certain types of cracking or reforming.

The fuel for the combustion step may be any fuel that can be combusted with oxygen, including, but not limited to, coal, coke, wood, biomass, solid wastes, oils and other natural and synthetic liquid fuels of all grades and types, and hydrocarbon-containing gas of any type, such as natural gas, landfill gas, coal mine gas, gasifier syngas, or the like.

The oxygen with which the fuel is combusted may be supplied in the form of high purity oxygen, oxygen--enriched air, normal air or any other suitable oxygen-containing mixture.

The carbon dioxide capture step may he carried out using membrane or non-membrane technology, and may involve one or more than one type of separation procedure. In the event that membrane technology is used in whole or part for this step, the capture step remains a discrete unit operation separate from the subsequent membrane separation step, 18.

Representative methods that may be used to capture carbon dioxide in this step include, but are not limited to, physical or chemical sorption, membrane separation, compression/low temperature condensation, adsorption, or any other known technology. Preferred technologies are absorption, such as amine scrubbing or chilled ammonia sorption, condensation, membrane separation, and combinations of these.

Low-temperature or cryogenic condensation and absorption into an amine solution are the most common methods in current industrial use for capturing carbon dioxide and need no detailed description herein. Either method is well suited for use in the present invention. Methods of recovering liquid carbon dioxide by cryogenic condensation or distillation are well known in the art. Preferred processes include variants of the well-known Ryan-Holmes process, in which a light hydrocarbon liquid or liquid mixture is added to the column to prevent formation of carbon dioxide solids or azeotropes in the column. Various specific techniques for carrying out low temperature condensation are taught, for example in U.S. Pat. Nos. 4,371,381; 4,923,493; 5,233,837. The Ryan-Holmes process is taught in U.S. Pat. Nos. 4,350,511 and 4,462,814, for example.

Methods of recovering carbon dioxide by absorption are also commonly used. In brief, these methods involve absorbing the carbon dioxide into a sorbent solution by physical or chemical interaction, then stripping the gas from the solution and recirculating the regenerated sorbent. Various sorbents may be used; most commonly the sorbent is amine-based and may include a single alkanolamine or a mix of amines. Other sorbents that may be used include chilled ammonia, as in the Alstom process, or other specialized proprietary solvents.

The sorbent solution may be regenerated by steam stripping, and the carbon dioxide recovered from the stripping vapor by cooling and condensing the water. A representative process of this type that may be used is the Fluor Daniel Econamine FG™ process, which uses a monoethanolamine (MEA) based sorbent system. Very detailed descriptions of such processes can be found in the literature, for example in Gas Purification, A. Kohl and R. Nielsen (Fifth Edition, Gulf Publishing Co., Houston, Tex., 1997), pages 1188-1237.

It is less preferred to use membrane separation alone for the carbon dioxide capture step as it is hard to reach a high carbon dioxide concentration in the permeate stream without using multiple membrane stages. An example of a three-stage membrane unit for carbon dioxide recovery from natural gas streams is given in U.S. Pat. No. 6,648,944.

Two or more different separation technologies may also be combined in this step; membrane separation may be combined with cryogenic condensation, either upstream or downstream of the condensation step, for example, or gas released in the stripping step of the absorption process may be liquefied by condensation. Examples of such combined processes are taught in U.S. Pat. Nos. 4,639,257; 4,990,168; 5,233,837; and 6,085,549, for example, all of which are incorporated herein by reference.

The third unit operation is membrane separation. Turning to the membrane separation step, 18, as mentioned in the summary section, the membranes used in this step should exhibit high permeance for carbon dioxide, as well as high selectivity for carbon dioxide over nitrogen.

Any membrane with suitable performance properties may be used. Many polymeric materials, especially elastomeric materials, are very permeable to carbon dioxide. Preferred membranes for separating carbon dioxide from nitrogen or other inert gases have a selective layer based on a polyether. A number of such membranes are known to have high carbon dioxide/nitrogen selectivity, such as 30, 40, 50 or above. A representative preferred material for the selective layer is Pebax®, a polyamide-polyether block copolymer material described in detail in U.S. Pat. No. 4,963,165.

The membrane may take the form of a homogeneous film, an integral asymmetric membrane, a multilayer composite membrane, a membrane incorporating a gel or liquid layer or particulates, or any other form known in the art. If elastomeric membranes are used, the preferred form is a composite membrane including a microporous support layer for mechanical strength and a rubbery coating layer that is responsible for the separation properties.

The membranes may be manufactured as flat sheets or as fibers and housed in any convenient module form, including spiral-wound modules, plate-and-frame modules and potted hollow-fiber modules. The making of all these types of membranes and modules is well known in the art. To provide countercurrent flow of the sweep gas stream, the modules preferably take the form of hollow-fiber modules, plate-and-frame modules or spiral-wound modules.

Flat-sheet membranes in spiral-wound modules is the most preferred choice for the membrane/module configuration. A number of designs that enable spiral-wound modules to be used in counterflow mode with or without sweep on the permeate side have been devised. A representative example is described in U.S. Pat. No. 5,034,126, to Dow Chemical.

Membrane step or unit 18 may contain a single membrane module or bank of membrane modules or an array of modules. A single unit or stage containing one or a bank of membrane modules is adequate for many applications. If the residue stream requires further purification, it may be passed to a second bank of membrane modules for a second processing step. If the permeate stream requires further concentration, it may be passed to a second bank of membrane modules for a second-stage treatment. Such multi-stage or multi-step processes, and variants thereof, will be familiar to those of skill in the art, who will appreciate that the membrane separation step may be configured in many possible ways, including single-stage, multistage, multistep, or more complicated arrays of two or more units in serial or cascade arrangements.

Although the membrane modules are typically arranged horizontally, a vertical configuration may in some cases be preferred to reduce the risk of particulate deposition on the membrane feed surface.

Turning to the operating conditions of sweep-based membrane separation step 18, the separation of components achieved by the membrane unit depends not only on the selectivity of the membrane for the components to be separated, but also on the pressure ratio.

By pressure ratio, we mean the ratio of total feed pressure/total permeate pressure. In pressure driven processes, it can be shown that the enrichment of a component (that is, the ratio of component permeate partial pressure/component teed partial pressure) can never be greater than the pressure ratio. This relationship is true, irrespective of how high the selectivity of the membrane may be.

Further, the mathematical relationship between pressure ratio and selectivity predicts that whichever property is numerically smaller will dominate the separation. Thus, if the numerical value of the pressure ratio is much higher than the selectivity, then the separation achievable in the process will not be limited by the pressure ratio, but will depend on the selectivity capability of the membranes. Conversely, if the membrane selectivity is numerically very much higher than the pressure ratio, the pressure ratio will limit the separation. In this case, the permeate concentration becomes essentially independent of the membrane selectivity and is determined by the pressure ratio alone.

High pressure ratios can be achieved by compressing the feed gas to a high pressure or by using vacuum pumps to create a lowered pressure on the permeate side, or a combination of both. However, the higher the selectivity, the more costly in capital and energy it becomes to achieve a pressure ratio numerically comparable with or greater than the selectivity.

From the above, it can be seen that pressure-driven processes using membranes of high selectivity for the components to be separated are likely to be pressure-ratio limited. For example, a process in which a membrane selectivity of 40, 50, or above is possible (such as is the case for many carbon dioxide/nitrogen separations) will only be able to take advantage of the high selectivity if the pressure ratio is of comparable or greater magnitude.

The inventors have overcome this problem and made it possible to utilize more of the intrinsic selective capability of the membrane by diluting the permeate with the sweep gas (stream 21 in FIG. 1), thereby preventing the permeate side concentration building up to a limiting level.

This mode of operation can be used with a pressure ratio of 1, that is, with no total pressure difference between the feed and permeate sides, with a pressure ratio less than 1, that is, with a higher total pressure on the permeate side than on the feed side, or with a relatively modest pressure ratio of less than 10 or less than 5, for example.

The driving force for transmembrane permeation is supplied by lowering the partial pressure of the desired permeant on the permeate to a level below its partial pressure on the feed side. The use of the sweep gas stream 21 maintains a low carbon dioxide partial pressure on the permeate side, thereby providing driving force.

The partial pressure on the permeate side may be controlled by adjusting the flow rate of the sweep stream to a desired value. In principle the ratio of sweep gas flow to feed gas flow may he any value that provides the desired results, although the ratio sweep gas flow:feed gas flow will seldom be less than 0.1 or greater than 10, but will most typically be 2 or less. High ratios (that is, high sweep flow rate) achieve maximum carbon dioxide removal from the feed, but a comparatively carbon dioxide dilute permeate stream (that is, comparatively low carbon dioxide enrichment in the sweep gas exiting the modules). Low ratios (that is, low sweep flow rate) achieve high concentrations of carbon dioxide in the permeate, but relatively low levels of carbon dioxide removal from the feed.

Use of a too low sweep rate may provide insufficient driving force for a good separation, and use of an overly high sweep flow rate may lead to pressure drop or other problems on the permeate side, or may adversely affect the stoichiometry in the reaction vessel.

Typically and preferably, the flow rate of the sweep stream should be between about 20% and 200% of the flow rate of the membrane feed stream, and most preferably between about 80% and 120%. Often a ratio of about 1:1 is convenient and appropriate.

The total gas pressures on each side of the membrane may be the same or different, and each may be above or below atmospheric pressure. As mentioned above, if the pressures are about the same, the entire driving force is provided by the sweep mode operation.

In most cases, however, flue gas is available at atmospheric pressure, and the volumes of the streams involved are so large that it is not preferred to use either significant compression on the feed side or vacuum on the permeate side. However, slight compression, such as from atmospheric to 1.1 to 2 bar, can be helpful and can provide part of a total carbon dioxide capture and recovery process that is relatively energy efficient, as shown in the examples below.

The process embodiment disclosed in the '020 patent in which the carbon dioxide capture step includes membrane separation is shown in FIG. 2. It will be appreciated by those of skill in the art that this, like FIG. 1 and the other flow schemes shown herein, is a very simple block diagram, intended to make clear the key unit operations of the process of the invention, and that an actual process train will usually include many additional steps of a standard type, such as heating, chilling, compressing, condensing, pumping, various types of separation and/or fractionation, as well as monitoring of pressures, temperatures and flows, and the like. It will also be appreciated by those of skill in the art that the details of the unit operations may differ from case to ease.

Referring to FIG. 2, fuel, stream 24, and air, oxygen-enriched air or oxygen stream 36, are introduced into a combustor, 25.

Combustion off-gas stream, 26, is sent, at least in part, to the carbon dioxide capture step, in this case first membrane separation step or unit, 27. This unit contains membranes, 28, that are selectively permeable to carbon dioxide over nitrogen. This step may be pressure driven, by operating with a higher pressure on the feed side than on the permeate side. This may be achieved by compressing the feed, or more preferably, as the stream is smaller in volume, by pulling a partial vacuum on the permeate side, or by a combination of slight elevation of the feed pressure and slight vacuum on the permeate side.

This step separates the off-gas stream into a carbon dioxide concentrated permeate stream, 29, and a carbon dioxide depleted residue stream, 30. The permeate stream will also typically be rich in water vapor, which may be easily condensed by cooling the stream. Optionally, the permeate stream may then be sent to compression/low-temperature condensation or distillation to form a high purity carbon dioxide product.

Optionally, the driving force in the first membrane separation step may be augmented by using a steam sweep on the permeate side of the membrane. This can provide a significant improvement in the separation achieved in this step, as well as a reduction in energy consumption, since the steam used can be recovered from the permeate gas by simple condensation before the gas enters the vacuum pump.

Residue stream, 30, is passed as feed to second membrane separation unit or step, 31, containing membranes, 32, that are selectively permeable to carbon dioxide over nitrogen and to carbon dioxide over oxygen.

The residue stream flows across the feed side and a sweep gas of air, oxygen-enriched air or oxygen, stream 34, is introduced to the permeate side inlet of the membrane unit and flows across the permeate side, preferably in a flow pattern that is at least partly or substantially countercurrent to the flow pattern on the feed side. The ratio of the inlet flow rates of the feed and sweep streams is most preferably maintained at roughly 1:1, such that the sweep stream flow rate is between about 80% and 120% of the feed flow rate.

The resulting permeate/sweep stream, 35, is withdrawn from the membrane unit and is combined with stream 36 as feed 37 to the combustor. Optionally, stream 36 may be omitted and the entirety of the oxygen-containing stream 37 may be provided by sweep stream 35,

The residue stream, 33, is depleted in carbon dioxide and is discharged from the process. By following the teachings of the invention, it is possible to reduce the carbon dioxide concentration of the discharged off-gas by at least 80%, 90%, or more compared with the concentration in the raw flue gas. For example, the off-gas from the combustor may contain 20% carbon dioxide and the residue vent gas may contain only 1 or 2% carbon dioxide.

Such a high level of carbon dioxide removal is practically impossible with processes that are purely pressure driven, as the energy requirements to operate the process and the membrane area needed to reach the desired levels of carbon dioxide permeation are excessive.

The process is now described in more detail as it relates to a specific preferred embodiment for treating flue gas from a power plant, such as a coal--fired power plant. In this representative process, the carbon dioxide capture step is assumed to be made up of a membrane separation stage, which is similar in function to membrane separation step 27 in FIG. 2, plus a third membrane separation step and a carbon dioxide recovery step that yields a liquid or supercritical fluid purified carbon dioxide product. The third membrane separation step and the product recovery step may be carried out with the membrane separation step preceding the product recovery step or vice versa.

A process described in the '020 patent in which the membrane separation step precedes a liquefaction step for product recovery is shown schematically in FIG. 3, Referring to this figure, flue gas stream, 41, emanates from the combustors of a power plant, 40, which is fed by stream 39, made up of fuel stream, 38, and air stream, 49. In most coal- or gas-fired power plants, the pressure of this flue gas is just above atmospheric, such as 1.1 or 1.2 bar absolute. However, in some processes, for example, combustion of natural gas for an electric power generation turbine, the flue gas pressure may be higher, such as 2-10 bar.

The flue gas passes to the first section of the carbon dioxide capture step, specifically first membrane separation step, 42. The step is carried out using membranes, 43, having carbon dioxide permeance and selectivity characteristics as described above. This step separates the flue gas into a carbon dioxide depleted residue stream, 44, usually containing less than about 10% carbon dioxide, and a carbon dioxide enriched permeate stream, 50, usually containing at least about 40% carbon dioxide.

In deciding the operating conditions for the membrane separation step, there exists a trade-off between the amount of membrane area required for the separation and the energy consumption to operate the process. In this representative and preferred example, the driving force for transmembrane permeation in this step is shown as being provided by a vacuum pump or train of vacuum pumps, 51, on the permeate side of the first membrane step. The vacuum pumps maintain a pressure down to about 0.1 bar, such as 0.5 bar or 0.2 bar on the permeate side.

The pressure difference across the membrane generated by the vacuum pump(s) is small, so the membrane areas required to achieve the separation required are very large. However, the permeate gas stream passing through the vacuum pump has only a fraction of the volume of the flue gas, so the power used by the vacuum pump is smaller than the power that would be consumed by a compression train operating on the feed gas.

Alternative preferred representative embodiments within the scope of the invention use modest compression of the feed stream, either alone or in conjunction with pulling a slight vacuum on the permeate side. An embodiment with slight feed compression is preferred, for example, in the case of a coal-fired power plant where the flue gas is at 1.1 bar absolute. This gas may be compressed to up to about 5 bar, such as 2 or 3 bar, and a portion of the energy used for the compressors maybe recovered by expanding the final treated flue gas stream, 47, in a turbine before final discharge. The use of connected compressor/turbo-expander operations for energy recovery is well known in the art and in power plants in particular.

Aftercooler, 52, knocks out water that has permeated the membranes with the carbon dioxide,

The remaining permeate gas stream, 53, then passes through a compressor or compression train, 54, where it is compressed to a few bar pressure, such as 3 or 4 bar, and then through aftercooler, 55, where additional water is knocked out. The compressed gas foetus the feed stream, 56, to the second membrane separation stage, 57, containing membranes, 58, having similar characteristics to those described previously. The permeate stream, 60, from this stage typically contains more than 80% carbon dioxide, and is sent to a cryogenic liquefaction plant, 61, to produce liquefied carbon dioxide product, 62.

The off-gases, 63, from the liquefaction plant, which are mostly nitrogen and oxygen, but which also may contain up to 10, 15 or 20% carbon dioxide, may be returned to the front of the flue gas treatment train at position A as shown, may be returned to the combustor at position B as shown, or may be recirculated, used or discharged in any other desired fashion. Likewise, the residue stream, 59, from the second-stage membrane unit maybe returned to the process at position A or B, or sent elsewhere as desired.

The residue gas stream, 44, leaving the first membrane unit normally contains up to about 10% carbon dioxide. This gas passes as feed to the sweep-driven membrane separation step or unit, 45. This step uses membranes, 46, having similar characteristics to those described previously. The feed air, 48, to the power plant burner passes as a sweep gas on the other side of the membranes. Carbon dioxide permeates preferentially through the membranes and is returned with the feed air to the burner in permeate/sweep stream, 49.

The treated flue gas stream, 47, is vented.

The embodiment described above with respect to FIG. 3 is intended to be illustrative of a typical flue gas treatment process and is not intended to limit the scope of the invention. Those of skill in the art will appreciate how to practice the invention as it applies to other combustion processes by following the teachings herein.

For example, a representative variant of the embodiment of FIG. 3 is shown in FIG. 4, in which like elements are numbered as in FIG. 3. The process of FIG. 3 differs from that of FIG. 4 in that some compression, 73, is used to create a compressed feed stream, 74, at 2 or 3 bar, which forms the feed to membrane separation step, 42.

This design also differs from that of FIG. 3 in the manner in which the compressed gas stream, 56, is processed. In FIG. 3, the stream passes to a membrane separation step, 57, and thence to the liquefaction plant. In FIG. 4, the membrane step is used instead to treat the off-gas from the liquefaction unit, so that the product recovery step precedes the last membrane separation step. Thus, stream 56 enters compression step or train, 64, where the pressure is raised to a suitable pressure for liquefaction, such as 20, 30, 40 bar or above, then passes as compressed stream, 65, to the condensation steps. 66. Here the gas is condensed/distilled at low temperature, typically by heat exchange against propylene or other low-temperature refrigerant, to produce carbon dioxide product stream, 67. The overhead stream, 68, from the carbon dioxide recovery column, is sent to membrane separation step, 69, containing membranes, 70, having similar characteristics to those described previously. The driving force for transmembrane permeation in this membrane unit is provided by the high pressure of the column overhead. The permeate stream, 72, is enriched in carbon dioxide and is recirculated at a suitable point to the compression train for the liquefaction steps, as indicated in the figure, or may be returned elsewhere in the process.

The membrane residue stream, 71, may be returned to the combustor, to the flue gas treatment train before or after compression step 73, or may be used or discharged elsewhere as desired.

In an alternative embodiment of the invention, described in the '715 patent, the carbon dioxide capture step and the sweep-based membrane separation step are performed in parallel, rather than in series or sequence (as in the '020 patent embodiments described above). Such parallel embodiments are especially useful for treating flue gas from power plants, for example. A portion of the exhaust stream from the combustion process is routed to a carbon dioxide capture step, and the other portion is routed to a sweep-based membrane separation step. A simple flow scheme for this embodiment of the invention is shown in FIG. 5.

Referring to FIG. 5, fuel stream 102 and air, oxygen-enriched air, or oxygen stream 104 are introduced into combustion step or zone 112. Stream 104 is made up of sweep stream 103 (discussed below) and, optionally, additional air or oxygen supply stream 115.

The combustion step, the fuel for the combustion step, and the oxygen with which the fuel is combined are as described above with respect to the previously disclosed embodiments of the invention.

Combustion exhaust stream 105—preferably containing at least 15 vol %, more preferably, at least 20 vol %; and, most preferably, at least 25 vol %, carbon dioxide—is withdrawn. This stream usually contains at least carbon dioxide, water vapor, and nitrogen, as well as the other components mentioned in the Summary section above. Combustion exhaust stream 105 is optionally but typically routed through a condenser 114, where the stream is cooled, knocking out excess water 110. The dehydrated exhaust stream 106 is then routed through a splitter 116, where it is divided in a desired ratio into a first portion 107 and a second portion 108.

The first portion 107 of exhaust stream 106 is routed to a carbon dioxide capture step 113. The carbon dioxide capture step may be earned out using any technology or combination of technologies that can create a concentrated carbon dioxide stream from the exhaust stream. The capture step yields a concentrated carbon dioxide product stream 117 preferably containing greater than 60, 70, or 80 vol % carbon dioxide or more this stream may be in the gas or liquid phase, or may be a supercritical fluid. The concentrated stream 117 may be sent for further processing in a sequestration step (not shown) to yield a liquid carbon dioxide product, for example, but alternatively may be used or disposed of in any other appropriate way.

The carbon dioxide capture step 113 may be carried out using membrane or non-membrane technology, and may involve one or more than one type of separation procedure. In the event that membrane technology is used in whole or part for this step, the capture step 113 remains a discrete unit operation separate from the simultaneous sweep-based membrane separation step 111.

Representative methods that may be used to capture carbon dioxide in this step include, but are not limited to, physical or chemical sorption, membrane separation, compression/low temperature condensation, adsorption, or any other known technology. Preferred technologies are absorption, such as amine scrubbing or chilled ammonia sorption, condensation, membrane separation, cryogenic condensation, and combinations of these. If membrane separation is used for the carbon dioxide capture step, it is preferred to use two or more membrane separation steps, as it is hard to reach a high carbon dioxide concentration in the permeate stream without using multiple membrane stages. Each of these methods of carbon dioxide capture is discussed in detail above, with respect to the previously disclosed embodiments of the invention, and such details are equally applicable to the present embodiments.

A second portion 108 of combustion exhaust stream 106 is sent for treatment in membrane separation step or unit 111. The membrane separation unit 111 contains membranes 118 that exhibit high permeance for carbon dioxide, as well as high selectivity for carbon dioxide over nitrogen. The separation of components achieved by the membrane unit depends not only on the selectivity of the membrane for the components to be separated, but also on the pressure ratio. Suitable membranes, membrane modules, and methods of achieving desired feed pressure/permeate pressure ratios are described in detail above with respect to the previously disclosed embodiments of the invention, and such details are equally applicable to the present embodiments.

The second portion 108 of combustion exhaust stream 106 flows across the feed side of the membranes; a sweep gas of air, oxygen-enriched air, or oxygen stream 101, flows across the permeate side. The sweep stream picks up the preferentially permeating carbon dioxide, and the resulting permeate stream 103 is withdrawn from the membrane unit and is combined with stream 115 to form the air or oxygen feed 104 to the combustor. In the alternative, stream 115 may be omitted and the entirety of the oxygen-containing feed to the combustor may be provided by the permeate stream 103.

As discussed previously, one of the additional benefits of using the combustion air or oxygen supply as the permeate sweep is that the permeating carbon dioxide removed into the sweep gas is recycled to the combustion chamber. This increases the carbon dioxide concentration in the exhaust gas leaving the combustor, facilitating the downstream capture of carbon dioxide.

The residue stream 109 resulting from the membrane sweep step 111 is reduced in carbon dioxide content to less than about 5 vol %, more preferably, to less than 3 vol %, and, most preferably, to less than 2 vol %. The residue stream 109 is discharged to the environment as treated flue gas,

The proportions of the flue gas that are directed to the carbon dioxide capture step and the sweep-based membrane separation step may be adjusted in conjunction with other operating parameters to tailor the processes of the invention to specific circumstances.

One of the goals of the process is to increase the carbon dioxide concentration in the feed stream to the carbon dioxide capture step, because many capture technologies, such as amine scrubbing and cryogenic condensation, have capital and/or operating costs that scale with the concentration of the component to be captured. The membrane separation step preferentially permeates carbon dioxide and returns it to the combustor, thereby forming a loop between the combustor and the membrane unit in which the carbon dioxide concentration can build up.

The more exhaust gas that is directed to the membrane unit, in other words, the smaller the split ratio, the greater is the potential to increase the carbon dioxide concentration in the loop. However, the amount of membrane area needed will increase in proportion to the volume flow of gas directed to the membrane unit. Furthermore, most membrane materials have slight selectivity for oxygen over nitrogen, so a little oxygen from the air sweep stream will tend to counter-permeate to the feed side of the membranes and be lost in the residue stream. In consequence, the concentration of oxygen in the combustor may drop, giving rise to the possibility of incomplete combustion, coke formation on boiler components, or other problems. As illustrated by the calculations given, in the Examples section below, we have discovered that trade-offs exist between the degree of carbon dioxide enrichment that can be obtained by the membrane separation steps, the amount of oxygen lost into the residue stream, and the membrane area and compression requirements to operate the membrane separation step.

In light of these trade-offs, we believe that it is preferable to operate the process at a split ratio of between 1:10 and 3:1. A split ratio of 1:1 means that splitter, 116, divides the total flue gas flow from the combustor into two equal portions by volume, so that 50 vol % passes to the carbon dioxide capture step and 50 vol % passes to the membrane separation step. Likewise, a split ratio of 1:10 means that 9 vol % passes to the carbon dioxide capture step and 91 vol % passes to the membrane separation step, and so on. More preferably, we prefer to operate at a split ratio between 1:4 and 2:1; that is, with between 20 vol % and 65 vol % of the exhaust being directed to the carbon dioxide capture step. We have discovered that operating in this range will provide a good balance between efficiency and costs for most processes.

The choice of the optimum split ratio will depend on many case-dependent factors. For example, in certain cases, the gas may be burnt with an excess of air, so that the flue gas produced only contains 4-6 vol % carbon dioxide and 10-15 vol % oxygen. This low carbon dioxide concentration makes capture of carbon dioxide for sequestration expensive. As shown in the Examples that follow, this concentration can be increased to 30 vol % (a six-fold increase) or more by using the membrane process with a large split ratio (1:5 or even 1:10). A large split ratio implies a large membrane area (capital cost) for unit 118 in FIG. 5, but this is offset by the smaller size of the carbon dioxide capture unit 113.

In certain eases, the gas being burnt already contains some carbon dioxide, so the flue gas produced can contain 20 vol % carbon dioxide or more, In this case, although increasing the carbon dioxide concentration in the stream going to the capture process is beneficial, increasing the concentration more than two-fold begins to reach a point of diminishing returns. In this case, the split ratio will be smaller—perhaps 1:1 or 1:2—as the trade-off between the cost of the membrane unit 118 required to the cost of the carbon dioxide capture step 113 favors a low split ratio>

FIG. 6 is a schematic drawing of a flow scheme for an embodiment of the invention described in the '715 patent, which is a variant of the flow scheme shown in FIG. 5, and in which the portion of the exhaust stream being routed to the sweep-based membrane separation step is passed through a compressor prior to being sent to the membrane separation step. Such embodiments are preferred in situations where the energy costs of the compression step can be tolerated, such as when energy can be recovered in a turbo-expander, as discussed with respect to the series embodiments of the invention above,

Referring to FIG. 6, fuel stream 202 and air, oxygen-enriched air, or oxygen stream 204 are introduced into combustion step or zone 212. Stream 204 is made up of sweep stream 203 and, optionally, additional air or oxygen supply stream 215.

Combustion exhaust stream 205—preferably containing at least 15 vol %; more preferably, at least 20 vol %; and, most preferably, at least 25 vol %, carbon dioxide—is withdrawn. Combustion exhaust stream 205 is typically routed through a condenser 214, where water 210 is knocked out of the stream. The dehydrated exhaust stream 206 is then routed through splitter 216, where it is divided in a desired ratio into first portion 207 and second portion 208.

The first portion 207 of exhaust stream 206 is routed to carbon dioxide capture step which yields a concentrated carbon dioxide product stream 217.

The second portion 208 of combustion exhaust stream 206 is then routed through a compressor 219, where it is compressed to a pressure of up to about 5 bar—such as 2 bar—prior to being sent for treatment in membrane separation step or unit 211, which contains membranes 218 that exhibit high permeance for carbon dioxide, as well as high selectivity for carbon dioxide over nitrogen. The second portion 208 of combustion exhaust stream 206 flows across the feed side of the membranes; a sweep gas of air, oxygen-enriched air, or oxygen stream 201, flows across the permeate side. The sweep stream picks up the preferentially permeating carbon dioxide, and the resulting permeate stream 203 is withdrawn from the membrane unit and is combined with stream 215 to form the air or oxygen feed 204 to the combustor. In the alternative, stream 215 may be omitted and the entirety of the oxygen-containing feed to the combustor may be provided by the permeate stream 203.

The residue stream 209 resulting from the membrane sweep step, which is discharged to the environment as treated flue gas, is reduced in carbon dioxide content to less than about 5 vol %. more preferably, to less than 4 vol %; and, most preferably, to less than 3 vol %.

FIG. 7 is a schematic drawing of a flow scheme for an embodiment of the invention described in the '715 patent, which is a variant of the flow scheme shown in FIG. 5, and in which the carbon dioxide capture step comprises two membrane-based capture steps.

Referring to FIG. 7, fuel stream 302 and air, oxygen-enriched air, or oxygen stream 304 are introduced into combustion step or zone 320. Stream 304 is made up of sweep stream 303 and, optionally, additional air or oxygen supply stream 321.

Combustion exhaust stream 305—preferably containing at least 15 vol %; more preferably, at least 20 vol %; and, most preferably, at least 25 vol %, carbon dioxide—is withdrawn. Combustion exhaust stream 305 is typically routed through a condenser 322, where water 315 is knocked out of the stream. The dehydrated exhaust stream 306 is then routed through splitter 316, where it is divided in a desired ratio into first portion 307 and second portion 308.

The first portion 307 of exhaust stream 306 is then routed through a compressor 323, where it, is compressed to a pressure of up to about 5 bar, followed by a condenser 324, where water 325 is knocked out of the stream. The dehydrated stream 309 is routed to a carbon dioxide capture process, which in this embodiment comprises two membrane-based capture steps, 326 and 328. The membrane units 326 and 328 contain membranes 327 and 329, respectively, that exhibit high permeance for carbon dioxide, as well as high selectivity for carbon dioxide over nitrogen.

The permeate stream 311 from the first membrane unit 326 yields a high-purity carbon dioxide product. The residue stream 310 from the first membrane unit 326 is routed to second membrane unit 328 to remove carbon dioxide remaining in the first residue stream before the stream is discharged. The permeate stream 312 from the second membrane unit 328 is passed to the sweep-based membrane separation step 330. The carbon-dioxide depleted residue stream 313 is typically exhausted to the environment.

The second portion 308 of combustion exhaust stream 306 and the permeate stream 312 from the second membrane-based capture step 328 are then sent for treatment in membrane separation step or unit 330, which contains membranes 318 that exhibit high permeance for carbon dioxide, as well as high selectivity for carbon dioxide over nitrogen. The second portion 308 of combustion exhaust stream 306 and the permeate stream 312 from the second membrane-based capture step 328 flow across the feed side of the membranes; a sweep gas of air, oxygen-enriched air, or oxygen stream 301, flows across the permeate side. The sweep stream picks up the preferentially permeating carbon dioxide, and the resulting permeate stream 303 is withdrawn from the membrane unit and is combined with stream 321 to form the air or oxygen feed 304 to the combustor. In the alternative, stream 321 may be omitted and the entirety of the oxygen-containing feed to the combustor may be provided by the permeate stream 303.

The residue stream 314 resulting from the membrane sweep step, which is discharged to the environment as treated flue gas, is reduced in carbon dioxide content to less than about 5 vol %, more preferably, to less than 4 vol %; and, most preferably, to less than 3 vol %.

FIG. 9 is a schematic drawing of a basic flow scheme for a flue gas treatment process in accordance with the present invention, in which at least a portion of an off-gas stream from the carbon dioxide capture step is routed as part of a feed stream to a sweep-based membrane separation step.

Referring to FIG. 9, fuel stream 502 and air, oxygen-enriched air, or oxygen stream 504 are introduced into combustion step or zone 512. Stream 504 is made up of sweep/permeate stream 503 and, optionally, additional air or oxygen supply stream 515.

Combustion exhaust stream 505—typically containing between about 10 vol % to about 25 vol % carbon dioxide—is withdrawn. Combustion exhaust stream 505 is typically routed through a condenser 514, where water 510 is knocked out of the stream. The dehydrated exhaust stream 506 is then routed through splitter 516, where it is divided in a desired ratio into first portion 507 and second portion 508.

The first portion 507 of exhaust stream 506 is routed to carbon dioxide capture step 513, which yields a concentrated carbon dioxide product stream 517. The carbon dioxide capture step preferably comprises at least one process selected from the group consisting of absorption, adsorption, liquefaction, and membrane separation. Typically, the capture step is an absorbent-based step, which may be either a chemical or a physical absorption process.

The absorption step may be carried out in any manner, and using any sorbent, that enables the bulk of the carbon dioxide to be removed from the first portion of the exhaust gas. Preferably the absorption step is performed by amine scrubbing, which has been used to separate carbon dioxide from natural gas and hydrogen since the 1930s. The technology, which involves absorption of carbon dioxide into an aqueous amine solution, followed by regeneration of the solution by stripping, is a well-understood and widely used process. The basic process was patented by R. R. Bottoms in 1930, under U.S. Pat. No. 1,783,901, the disclosure of which is hereby incorporated by reference in its entirety.

Carbon dioxide is absorbed from a fuel gas or combustion gas near ambient temperature into an aqueous solution of amine with low volatility. The amine sorbent may include a single alkanolamine or a mixture of amines. The sorbent solution may be regenerated by steam stripping, and the carbon dioxide recovered from the stripping vapor by cooling and condensing the water. A representative process of this type that may be used is the Fluor Daniel Econamine FG™ process, which uses a monoethanolamine (MEA) based sorbent system. Very detailed descriptions of such processes can be found in the literature, for example in Gas Purification, A. Kohl and R. Nielsen (Fifth Edition, Gulf Publishing Co., Houston, Tex., 1997), pages 1188-1237.

As one possible representative alternative to amine scrubbing, an absorption process using chilled ammonia may be used. In such a process, the flue gas is first cooled to condense and remove moisture and residual pollutants before it enters the carbon dioxide absorber. There, the carbon dioxide is absorbed by an ammonia-based solution, separating it from the flue gas.

Another possible alternative to amine absorption is absorption with potassium carbonate, sometimes called the Benfield process or the “Hot Pot” process. These systems are known as “activated hot potassium carbonate” (AHPC) systems. In this process, cool potassium carbonate reacts with carbon dioxide to form potassium bicarbonate. When the solution is heated in a desorption tower, the absorbed carbon dioxide is released.

Other alternative processes include the Rectisol® and Selexol® processes, both of which are well known in the chemical engineering industry. Rectisol and Selexol are trade names for solvents that separate acid gases, such as carbon dioxide and hydrogen sulfide, by physical sorption. Since no chemical reactions are involved, these processes typically require less energy than amine- or ammonia-based processes.

Rectisol uses a methanol solvent and has commonly been used to treat syngas produced by gasification of coal or heavy hydrocarbons, as the solvent can remove trace contaminants—such as ammonia, mercury, and hydrogen cyanide—typically found in these gases.

In the Rectisol process, cold methanol at approximately −40° F. (−40° C.) dissolves/absorbs the acid gases from the feed gas at relatively high pressure, usually 400 to 1,000 psia (2.76 to 6.89 MPa). The acid gas-rich solvent is then reduced in pressure to release and recover the acid gases. The Rectisol process can operate selectively to recover carbon dioxide and hydrogen sulfide as separate streams.

The Selexol solvent is a mixture of the dimethyl ethers of polyethylene glycol. The Selexol process also operates under pressure, typically around 300 to 2000 psia (2.07 to 13.8 Mpa). Like the Rectisol process, the acid gas-rich solvent is then reduced in pressure and/or steam-stripped to release and recover the acid gases, which can be selectively recovered as separate streams.

The choice of which of these processes to use will depend on the specifics of the particular application. However, absorption with MEA (monoethanolamine) is a common choice in post-combustion carbon dioxide sequestration applications. MEA is used because it rapidly and very efficiently removes carbon dioxide from the carbon dioxide-containing combustion exhaust gas. However, for the MFA to work propertly, the carbon dioxide-loaded amine solution from the absorption operation must be heated to a high temperature to strip carbon dioxide from the liquid, and to regenerate carbon dioxide-free MEA solution. This regeneration step consumes a large amount of energy and can cause a portion of the MEA to degrade.

In the process illustrated in FIG. 9, complete removal of carbon dioxide from stream 519 is not required. This stream can contain 8 to 10 vol % carbon dioxide because, after treatment in the sweep-based membrane separation step 511, most of the remaining carbon dioxide will be removed. Allowing a portion 508 of the carbon dioxide in the exhaust gas 506 to “slip” through the carbon dioxide removal step is very beneficial and allows for the regeneration conditions of the MEA to be significantly eased. This reduces the energy consumption of the MFA absorption processes, as well as having a number of other operational benefits.

If desired, amine scrubbing or other sorption may be combined in this step with one or more other known gas separation technologies. Examples of such technologies include, but are not limited to, membrane separation, compression/low temperature condensation, and adsorption.

The second portion 508 of combustion exhaust stream 506 and at least a portion 519 of the capture step off-gas stream are passed as a feed stream, 520, to a membrane separation step or unit 511, which contains membranes 518 that exhibit high permeance for carbon dioxide, as well as high selectivity for carbon dioxide over nitrogen.

In accordance with preferred embodiments of the present invention, two gas streams (506 and 519) are to be treated in the sweep-based membrane separation step 511. Most simply, the two steams may be combined and treated as a single stream by the membrane sweep unit. But combining the two streams may be done at an intermediate point in the process where the stream compositions are similar, as described above in the “Summary of the Invention”.

Feed stream 520 flows across the feed side of the membranes; a sweep gas of air, oxygen-enriched air, or oxygen stream 501, flows across the permeate side. The sweep stream picks up the preferentially permeating carbon dioxide, and the resulting sweep/permeate stream 503 is withdrawn from the membrane unit and is combined with stream 515 to form the air or oxygen feed 504 to the combustor. In the alternative, stream 515 may be omitted, and the entirety of the oxygen-containing feed to the combustor may be provided by the sweep/permeate stream 503.

The residue stream 509 resulting from the membrane sweep step, which is discharged to the environment as treated flue gas, is reduced in carbon dioxide content to less than about 5 vol %; more preferably, to less than 3 vol % or 2 vol % and often, to 1 vol % or less.

Referring now to FIG. 12, which illustrates an embodiment of the invention used to separate and concentrate carbon dioxide created by the burning of coal to make electricity in a coal power plant. Unit 901 represents the boiler, where coal and incoming oxygen-containing stream 921 are burnt to make heat that powers a steam turbine. (Stream 921 typically comprises permeate/sweep stream 914 and, optionally, an additional stream 916 of air, oxygen-enriched air, or oxygen.)

Normally, the flue gas 908 from the process should contain between 10 to 13 vol % carbon dioxide, however, because of the process of the invention (described in further detail below), the gas is enriched in carbon dioxide and can contain from 15 to 20 vol % carbon dioxide.

A first portion, 909 of exhaust gas stream 908 is sent to a membrane separation unit, 902, that contains membranes, 917, that are preferentially permeable to carbon dioxide over nitrogen, and to carbon dioxide over oxygen. Membrane separation step 902 lowers the carbon dioxide content of the exhaust gas from about 20 vol % to about 5 to 10 vol %, The driving force to generate permeation in membrane unit 902 is created by a vacuum pump, 903.

The carbon dioxide concentrate stream, 915, thus produced is enriched to 70 to 80 vol % carbon dioxide, and possibly more, depending on the selectivity of the membrane and the low pressure generated by vacuum pump 903.

A second portion, 911, of exhaust stream 908 is sent to two consecutive sweep-based membrane separation units, 904 and 905, that contain first and second membranes, 918 and 920, respectively, that are preferentially permeable to carbon dioxide over nitrogen, and to carbon dioxide over oxygen. A sweep stream, 907, of air, oxygen-enriched air, or oxygen flows across the permeate side of second membrane 920. Stream 911 flows across the feed side of first membrane 918.

Residue stream 910 from membrane separation unit 902 joins the residue stream, 912, from the first sweep-based membrane unit 904 and passes as a feed stream 919 to second sweep-based membrane unit 905.

The two sequential sweep-based membrane operations (904 and 905) reduce the carbon dioxide concentration in flue gas 911 from 15 to 20 vol %, to about 5 to 10 vol % in the residue stream from the first sweep-based step 904, and to less than about 2 vol % in the residue stream, 913, from the second sweep-based step 905. Residue stream 913 is typically vented to the environment.

The driving force to remove the carbon dioxide from membrane feed streams 911 and 919 is generated by the air sweep 907 that travels countercurrent to the feed gases on the permeate sides of the membranes.

An important feature of this invention is that residue stream 910 from membrane separation unit 902 does not need to be reduced to a very low carbon dioxide concentration. This is beneficial, as it reduces the size of membrane unit 902 and vacuum pump 903 and, most importantly, maintains the carbon dioxide content of product stream 915 at a high concentration.

The remaining carbon dioxide in stream 910 is removed by treating the stream with either first membrane sweep unit 904, or second membrane sweep unit 905. In one embodiment, stream 910 at about 5 vol % carbon dioxide) is mixed with stream 911 (at about 20 vol % carbon dioxide) upstream of first sweep unit 904 (as indicated by the broken line in FIG. 12). This is mechanically the simplest way to treat stream 910, and could be used in many processes.

However, a better way to treat stream 910 is to introduce it at some intermediate point in the membrane sweep system, such as prior to second sweep unit 905 (as indicated by the solid line in FIG. 12). Streams 910 and 912 (the partially treated residue streams from membrane units 902 and 904 respectively)) both contain about the same concentration of carbon dioxide, so mixing losses from the process are minimized.

The sweep/permeate stream 922 from second sweep operation 905 is used as the sweep stream for first sweep operation 904. The resulting permeate stream 914 from sweep operation 904 is recycled to coal boiler 901 as part of incoming air stream 921.

The overall result of this process is to separate the exhaust gas 908 from coal boiler 901 into two streams: a carbon dioxide concentrate stream 915, and a carbon dioxide depleted stream 913,

The invention is now further described by the following examples, which are intended to be illustrative of the invention, but are not intended to limit the scope or underlying principles in any way.

EXAMPLES Example 1 Bases of Calculations for Other Examples

(a) Membrane permeation experiments: Sets of permeation experiments were performed with two different composite membranes, each having a polyether-based selective layer. The properties of the membranes as measured with a set of pure gases at 6.7 bar absolute and 30° C. are shown in Tables 1 and 2.

TABLE 1 Gas Permeance (gpu)* CO₂/Gas Selectivity Carbon dioxide 1,000   — Nitrogen 20 50 Oxygen 50 20 Methane 50 20 Water >2,000**   — *Gas permeation unit; 1 gpu = 1 × 10⁻⁶ cm³(STP)/cm² · s · cmHg **Estimated, not measured

The following calculations were performed using the membrane properties shown in Table 2.

TABLE 2 Gas Permeance (gpu)* CO₂/Gas Selectivity Carbon dioxide 1,000   — Nitrogen 30 33 Oxygen 60 17 Hydrogen 100  10 Water 5,000**  — *Gas permeation unit; 1 gpu = 1 × 10⁻⁶ cm³(STP)/cm² · s · cmHg **Estimated, not measured

(b) Calculation methodology: The computer calculations in all of the following Examples were performed using a modeling program, ChemCad 5.6 (ChemStations, Inc., Houston, Tex.) containing code developed by assignee's engineering group for applications specific to assignee's processes. For the calculations, all compressors and vacuum pumps were assumed to be 75% efficient. In each case, the modeling calculation was performed to achieve about 80-90% recovery of carbon dioxide from the flue gas stream.

(c) “No membrane” example: A computer calculation was performed to determine the chemical composition of untreated flue gas from a coal combustion process. The calculation was performed assuming that the flue gas to be treated was from a 500 MW gross power coal-fired power plant. It was assumed that the exhaust gas is filtered to remove particulate matter before passing to the membrane separation steps.

FIG. 8 is a schematic drawing of a flow scheme for a combustion process that does not include a sweep-based membrane separation step. Fuel stream 402 and air stream 401 are introduced into combustion step or zone 403. (The combustion step, the fuel for the combustion step, and the oxygen with which the fuel is combined are as described in the Detailed Description, above.)

Combustion exhaust stream 404 is withdrawn, then routed through a cooler/condenser 407, where water 405 is knocked out of the stream. The chemical composition of the resulting untreated flue gas stream 406 was then calculated. The results of this calculation are shown in Table 3.

TABLE 3 Stream Condenser Coal Air Stream Knockout Flue Gas Parameter (402) (401) (405) (406) Total Flow (kg/h) 132,000 2,280,000 62,160 2,349,600 Temperature (° C.) 25 25 40 40 Pressure (bar) 1.0 1.0 1.0 1.0 Component (vol %) Coal (carbon + 100.0 0 0 0 hydrogen) Oxygen 0 21.0 0 3.1 Nitrogen 0 79.0 0 77.8 Carbon Dioxide 0 0 0 11.7 Water 0 0 100 7.4

After the water vapor in the stream is condensed, the carbon dioxide concentration in the combustion exhaust stream is 11.7 vol %. Discharge of such a stream in its untreated form would release 10,000 tons of carbon dioxide into the atmosphere per day. On the other hand, the carbon dioxide concentration is too low to enable the stream to be treated economically by traditional means, such as absorption or low-temperature condensation.

Examples 2-8 Processes of the Invention Described in the '715 Patent: Modeling of Sweep-based Membrane Separation Step and Effect on Combustion Step

A set of calculations was performed to model the effect of various process parameters on the performance of the sweep-based membrane separation step and its effect on the combustion step. The calculations for Examples 2 through 8 were performed using the flow scheme shown in FIG. 5 and described in the Detailed Description, above. This flow scheme includes a sweep-based membrane separation step, 111.

To facilitate operation of the calculation software, the base case air flow provided to the combustor via the membrane permeate side was assumed to be about 740 m³/h (950 kg/h), compared with the typical air flow to a 500 MW power plant of about 1.8 million m³/h used for the calculation of Example 1. In other words, the scale of the calculations for Examples 2 through 8 was about 1/2,400 of the scale for a typical coal-fired power plant. This reduces membrane area proportionately, but does not affect the relative floss rates or compositions of the streams involved.

Example 2 Process of the Invention Described in the '715 Patent

In this example, the membrane area was assumed to be 400 m², and the combustion exhaust stream split ratio was set at 1:1 (flow to carbon dioxide capture step:flow to sweep-based membrane separation step). The separation was assumed to be performed using a membrane having permeation properties as in Table 2, The results of this calculation are shown in Table 4.

TABLE 4 Stream Gas to Condenser Capture Membrane Air Gas to Coal Knockout Step Feed Sweep Combustor Retentate Parameter (102) (110) (107) (108) (101) (103) (109) Total Flow (kg/h) 55 46 554 554 950 1100 404 Temperature (° C.) 25 40 40 40 25 33 25 Pressure(bar) 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Component (vol %) Coal (carbon + 100 0 0 0 0 0 0 hydrogen) Oxygen 0 0 1.6 1.6 21.0 17.5 5.2 Nitrogen 0 0 71.8 71.8 79.0 70.6 91.9 Carbon Dioxide 0 0 19.2 19.2 0 8.3 2.9 Water 0 100 7.4 7.4 0 3.6 0

Compared with the “no membrane” Example 1, the carbon dioxide content in the combustion exhaust stream 107 sent to the capture step is increased from 117 vol % to 19.2 vol %, and compared to Example 1, the volume of gas to be treated by the carbon dioxide capture step 113 is reduced almost in half. This reduction in gas volume and increase in carbon dioxide concentration reduces the cost of carbon dioxide capture by essentially all capture technologies. This reduction in cost can then bring carbon dioxide capture from coal-fired power plants and other large carbon dioxide combustion gas streams into an economically acceptable range.

The carbon dioxide concentration in the membrane residue stream is reduced to 2.9 vol %, and venting of this stream to the atmosphere would release about 1,000 tons of carbon dioxide per day from a 500 MW power plant. Comparing this Example with Example 1, it can be seen that the process is effective in capturing 90% of the carbon dioxide emitted from the combustion section of the power plant.

As can also be seen, however, use of the incoming air as the permeate sweep stream reduces the oxygen content in the air to the combustor from the normal 21 vol % to 17.5 vol %. As a result, the mass flow of oxygen to the combustor is reduced from 221 kg/h in the conventional, no membrane case to 207 kg/h, and the oxygen content of the combustion exhaust stream, 108, is reduced to 1.6 vol %. The low exhaust oxygen concentration indicates that a real combustion process might be compromised under these conditions, and that insufficient oxygen mass flow would be available to achieve complete combustion without modifying the combustor. This is, therefore, a workable but less preferred process configuration.

Example 3 Process of the Invention Described in the 715 Patent, with Increased Air Flow

In this set of calculations, the air flow to the process via the permeate sweep stream was increased incrementally, until the oxygen mass flow to the combustor was comparable with that of Example 1, and the calculation showed an oxygen content of 3 vol % in the combustor exhaust stream. All other operating parameters, including split ratio and membrane area, were the same as in Example 2. The results of the calculation are shown in Table 5.

TABLE 5 Stream Gas to Condenser Capture Membrane Air Gas to Coal Knockout Step Feed Sweep Combustor Retentate Parameter (102) (110) (107) (108) (101) (103) (109) Total Flow (kg/h) 55 44 596 596 1035 1182 450 Temperature (° C.) 25 40 40 40 25 33 25 Pressure (bar) 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Component (vol % Coal (carbon + 100 0 0 0 0 0 0 hydrogen) Oxygen 0 0 3.2 3.2 21.0 17.8 6.6 Nitrogen 0 0 72.0 72.0 79.0 71.1 90.3 Carbon Dioxide 0 0 17.4 17.4 0 7.4 3.1 Water 0 100 7.4 7.4 0 3.7 0

Although the oxygen content of the combustion exhaust stream 108 is increased to 3.2 vol %, the carbon dioxide content of the combustion exhaust stream, 108, was lower than in Example 2, at 17.4 vol %, and the carbon dioxide content of the treated flue gas, 109, was a little higher, at 3.1 vol %.

Example 4 Process of the Invention Described in the '715 Patent, with Split Ratio 1:2

In this set of calculations, the split ratio was changed to 1:2, that is, two volumes of exhaust gas were assumed to be sent to the membrane separation step for every volume of exhaust gas sent to the carbon dioxide capture step. The membrane area was again assumed to be 400 m², and the air flow rate in stream 101 was assumed to be the base calculation value of 950 kg/h. The results of the calculation are shown in Table 6.

TABLE 6 Stream Gas to Condenser Capture Membrane Air Gas to Coal Knockout Step Feed Sweep Combustor Retentate Parameter (102) (110) (107) (108) (101) (103) (109) Total Flow (kg/h) 55 54 384 768 950 1151 567 Temperature (° C.) 25 40 40 40 25 35 25 Pressure (bar) 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Component (vol %) Coal (carbon + 100.0 0 0 0 0 0 0 hydrogen) Oxygen 0 0 1.6 1.6 21.0 16.8 4.3 Nitrogen 0 0 69.7 69.7 79.0 67.8 89.2 Carbon Dioxide 0 0 21.3 21.3 0 10.6 6.4 Water 0 100 7.4 7.4 0 4.8 0.1

Increasing the relative volume of exhaust gas being treated in the membrane separation step results in a substantial increase in the concentration of carbon dioxide in the exhaust gas from the combustor. The exhaust gas has almost double the concentration of carbon dioxide compared with Example 1. Thus, use of the sweep-based membrane separation step in parallel with the carbon dioxide capture step could unload the carbon dioxide capture step proportionately; however, the oxygen content of the combustion exhaust stream, 108, has dropped to an undesirably low value (1.6 vol %) and the carbon dioxide content of the treated flue gas is relatively high (6.5 vol %).

Example 5 Process of the Invention Described in the '715 Patent, with Increased Membrane Area

To compensate for the adverse aspects of decreasing the split ratio as in Example 4, the membrane area was assumed to be doubled, to 800 m². As in Example 3, a set of calculations was performed, increasing the air intake incrementally to the process to bring the oxygen concentration of the flue gas stream from the combustor back to 3 vol % and the mass flow back to about 42 kg/h. This required the intake flow rate of air to be increased from 950 kg/h to 1,090 kg /h. All other operating parameters, including split ratio, were the same as in Example 4. The results of the calculation are shown in Table 7.

TABLE 7 Stream Gas to Condenser Capture Membrane Air Gas to Coal Knockout Step Feed Sweep Combustor Retentate Parameter (102) (110) (107) (108) (101) (103) (109) Total Flow (kg/h) 55 51 456 912 1090 1364 638.1 Temperature (° C.) 25 40 40 40 25 35 25 Pressure (bar) 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Component (vol %) Coal (carbon + 100 0 0 0 0 0 0 hydrogen) Oxygen 0 0 2.9 2.9 21.0 16.0 7.3 Nitrogen 0 0 67.8 67.8 79.0 66.5 89.6 Carbon Dioxide 0 0 21.8 21.8 0 12.7 3.1 Water 0 100 7.4 7.4 0 4.8 0

Compared with. Example 4, the carbon dioxide content of the combustion exhaust stream. 108, remained high (21.8 vol %). The oxygen content of the combustion exhaust stream, 108, was raised to almost 3 vol %, and the carbon dioxide content of the treated, flue gas, 109, was reduced to much lower level of 3.1 vol %. The process achieves about 82% recovery of carbon dioxide.

Example 6 Process of the Invention Described, in the '715 Patent, with Split Ratio 1:4

In this example, the split ratio was changed to 1:4; that is, four volumes of exhaust gas were assumed to be sent to the membrane separation, step for every volume of exhaust gas sent to the carbon dioxide capture step. The membrane area was again assumed to be 400 m², and the air flow rate in stream 101 was assumed to he the base case calculation value of 950 kg/h. The results of the calculation are shown in Table 8.

TABLE 8 Stream Gas to Condenser Capture Membrane Air Gas to Coal Knockout Step Feed Sweep Combustor Retentate Parameter (102) (110) (107) (108) (101) (103) (109) Total Flow (kg/h) 55 59 236 942 950 1182 710 Temperature (° C.) 25 40 40 40 25 37 25 Pressure (bar) 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Component (vol %) Coal (carbon + 100 0 0 0 0 0 0 hydrogen) Oxygen 0 0 1.6 1.6 21.0 16.4 3.8 Nitrogen 0 0 68.5 68.5 79.0 66.3 86.8 Carbon Dioxide 0 0 22.5 22.5 0 11.8 9.1 Water 0 100 7.4 7.4 0 5.5 0.3

Increasing the relative volume of exhaust has being treated in the membrane separation step results in a further increase in the carbon dioxide content of the combustion exhaust stream, 108, to 22.5 vol %; however, the oxygen content of the combustion exhaust stream, 108, is low (1.6 vol %) and the carbon dioxide content of the treated flue gas, 109, is high (9.1 vol %).

Example 7 Process of the Invention Described in the '715 Patent

As with Example 5, the membrane area and air intake were assumed to be increased to balance the less desirable effects of decreasing the split ratio. In this example the membrane area was assumed to be increased to 1,600 m², and the air flow, 101, was assumed to be increased to 1,200 kg/h. Other parameters are as in Example 6, including a split ratio of 1:4, The results of the calculation are shown in Table 9.

TABLE 9 Stream Gas to Condenser Capture Membrane Air Gas to Coal Knockout Step Feed Sweep Combustor Retentate Parameter (102) (110) (107) (108) (101) (103) (109) Total Row (kg/h) 55 56 340 1361 1200 1702 859 Temperature (° C.) 25 40 40 40 25 37 25 Pressure (bar) 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Component (vol %) Coal (carbon + 100 0 0 0 0 0 0 hydrogen) Oxygen 0 0 2.9 2.9 21.0 13.6 8.5 Nitrogen 0 0 62.0 62.0 79.0 60.8 88.1 Carbon Dioxide 0 0 27.7 27.7 0 19.9 3.3 Water 0 100 7.4 7.4 0 5.7 0.1

The combination of the lowered split ratio, increased membrane area, and increased air flow rate resulted in an increase of the carbon dioxide content of the combustion exhaust stream to 27.7 vol %. The oxygen content of the combustion exhaust stream, 108, was about 3 vol %, and the carbon dioxide content of the treated flue gas was lowered to 3.3 vol %. The process achieves about 75% carbon dioxide recovery.

Example 8 Process of the Invention Described in the '715 Patent, with the Addition of Oxygen

The process of the invention was assumed to be carried out as in Example 7, The only difference was that the air intake via the permeate sweep line was assumed to be at the base case flow rate value of 950 kg/h, and an additional 50 kg/h of pure oxygen was assumed to be introduced directly into the combustor as stream 115. The results of the calculation are shown in Table 10.

TABLE 10 Stream Gas to Condenser Capture Membrane Air Gas to Coal O₂ Knockout Step Feed Sweep Combustor Retentate Parameter (102) (101) (110) (107) (108) (101) (103) (109) Total Flow (kg/h) 55 50 58 306 1225 950 1485 690.4 Temperature (° C.) 25 25 40 40 40 25 37 25 Pressure (bar) 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Component (vol %) Coal (carbon + 100 0 0 0 0 0 0 0 hydrogen) Oxygen 0 100 0 3.0 3.0 21.0 12.4 9.7 Nitrogen 0 0 0 56.1 56.1 79.0 56.4 87.0 Carbon Dioxide 0 0 0 33.5 33.5 0 25.2 3.3 Water 0 0 100 7.4 7.4 0 6.0 0

With addition of make-up oxygen, the carbon dioxide content of the combustion exhaust stream, 108, is increased to 33.5 vol %. The oxygen content of the combustion exhaust stream, 108, is 3.0 vol %, and the carbon dioxide content of the treated flue gas, 109, is 3.3 vol %. The process achieves about 80% carbon dioxide recovery.

Example 9-10 Process of the Invention Described in the '715 Patent, with Compression of the Membrane Feed Stream

The calculations for Examples 9 and 10 were performed using the flow scheme shown in FIG. 6 and described in the Detailed Description, above. The flow scheme shown in FIG. 6 is a variant of the flow scheme shown in FIG. 5, in which the portion of the exhaust stream, 208, being routed to the sweep-based membrane separation step 211, is passed through a compressor, prior to being sent to the membrane separation step, 211.

Example 9 Process of the Invention Described in the '715 patent with Split Ratio 1:4

A calculation was performed using the results of Example 7 as basis, and again assuming a split ratio of 1:4. Iterative calculations showed that use of feed compression to 2 bar enables the membrane area to be reduced to 500 m², and the air flow, 201, to be reduced to 1050 kg/h. The results of the calculation are shown in Table 11.

TABLE 11 Stream Gas to Condenser Capture Membrane Gas to Retentate Coal Knockout Step Feed Air Sweep Combustor (209) Parameter (202) (210) (207) (208) (201) (203) Total Flow (kg/h) 55 63 327 1309 1050 1644 715 Temperature (° C.) 25 30 30 45 25 40 25 Pressure (bar) 1.0 1.0 1.0 2.0 1.0 1.0 2.0 Component (vol %) Coal (carbon + 100 0 0 0 0 0 0 hydrogen) Oxygen 0 0 2.9 2.9 21.0 14.3 5.9 Nitrogen 0 0 60.7 60.7 79.0 58.9 91.2 Carbon Dioxide 0 0 32.1 32.1 0 23.5 2.9 Water 0 100 4.3 4.3 0 3.3 0

The carbon dioxide content of the combustion exhaust stream, 208, is 32.1 vol %. The oxygen content of the combustion exhaust stream, 208, is just under 3 vol %, and the carbon dioxide content of the treated flue gas, 209, is 2.9 vol %. Recovery of carbon dioxide is about 85%.

Example 10 Process of the Invention Described in the '715 Patent, with Split Ratio 1:9

This Example illustrates the combined effect of slight compression and a low split ratio of 1:9. The calculation was performed assuming a membrane area of 600 m², and an intake air flow rate in stream 201 of 1,150 kg/h. The assumption for membrane area and air intake flow rate are higher than for Example 9, to balance the lower split ratio. The results of the calculation are shown in Table 12.

TABLE 12 Stream Gas to Condenser Capture Membrane Gas to Coal Knockout Step Feed Air Sweep Combustor Retentate Parameter (202) (210) (207) (208) (201) (203) (209) Total Flow (kg/h) 55 65 232 2085 1150 2327 909 Temperature (° C.) 25 30 30 45 25 43 25 Pressure (bar) 1.0 1.0 1.0 2.0 1.0 1.0 2.0 Component (vol %) Coal (carbon + 100 0 0 0 0 0 0 hydrogen) Oxygen 0 0 3.2 3.2 21.0 11.7 7.2 Nitrogen 0 0 50.1 50.1 79.0 48.9 89.3 Carbon Dioxide 0 0 42.4 42.4 0 35.7 3.5 Water 0 100 4.3 4.3 0 3.7 0

The carbon dioxide content of the combustion exhaust stream, 208, is increased to 42.4 vol %. The oxygen content of the combustion exhaust stream, 208, is 3.2 vol %, and the carbon dioxide content of the treated flue gas, 209, is 3.5 vol %. The recovery of carbon dioxide in this case drops to about 65%, but the very high carbon dioxide content in the feed stream to the carbon dioxide capture step provides a large benefit in terms of de-bottlenecking or reducing required capacity and operating costs for this step.

Examples 11 and 12 Processes of the Invention Described in the '715 Patent using Membrane Separation for the Carbon Dioxide Capture Step

The calculations for Examples 16 and 17 were performed using the flow scheme shown in FIG. 7 and described in the Detailed Description, above. The flow scheme shown in FIG. 7 is a variant of the flow scheme shown in FIG. 5, in which the carbon dioxide capture step comprises two membrane-based capture steps, 326 and 328.

Example 11 Process of the Invention Described in the '715 Patent, with Compression

This Example was calculated assuming approximately the same parameters as in Example 7; that is, a split ratio of 1:4, an air flow rate of 1,200 kWh, and a membrane area for the sweep-based membrane step of 1,600 m². The membrane areas for the two membrane-based capture steps, 326 and 328, were assumed to be 22 m² and 20 m², respectively. The results of the calculation are shown in Table 13.

TABLE 13 Stream Condenser Feed to CO2 CO2- CO2- Gas to Coal Overhead Capture CO2-vent rich lean Air Sweep Combustor Retentate Parameter (302) (308) (309) (311) (312) (313) (301) (303) (314) Total Flow 55 1364 334 134 35 165 1200 1712 886.3 (kg/h) Temp. (° C.) 25 30 40 39 37 37 25 29 25 Pressure 1.0 1.0 10.0 1.0 1.0 10.0 1.0 1.0 1.0 (bar) Component (vol %) Coal 100 0 0 0 0 0 0 0 0 (carbon + hydrogen) Oxygen 0 3.0 3.1 1.6 4.5 3.6 21.0 13.8 8.5 Nitrogen 0 63.1 65.4 18.8 59.2 93.4 79.0 61.3 87.7 Carbon 0 30.0 30.8 77.3 36.0 3.0 0 21.6 3.8 Dioxide Water 0 4.3 0.7 2.3 0.3 0.1 0 3.3 0

The feed gas, 309, to the two-step carbon dioxide capture process consists of 30.8 vol % carbon dioxide. The first carbon membrane capture step, 326, yields a concentrated carbon dioxide product, 311, containing 77.3 vol % carbon dioxide.

The feed stream, 310, from first membrane unit, 326, is routed to second membrane unit, 328, to recover more of the carbon dioxide from the stream. The permeate stream, 312, from the second membrane unit, 328, contains 36.0 vol % carbon dioxide, and is passed to the sweep-based membrane separation step, 330. The carbon-dioxide depleted feed stream, 313, from the second carbon dioxide capture step. 328, contains 3.0 vol % carbon dioxide. This stream is combined with the exhaust stream, 314, from the sweep-based membrane separation step, 330, which contains 3.8 vol % carbon dioxide, and is vented to the environment. Carbon dioxide is lost in both streams 313 and 314, so the recover of carbon dioxide is comparatively low, at about 65%.

Example 12 Process of the Invention Described in the '715 Patent, with Addition of Pure Oxygen

The calculations of Example 11 were repeated, but this time it was assumed that a make-up stream of 50 kWh of pure oxygen was added directly to the combustor, as in Example 8, so that the air intake via the permeate sweep line was reduced to the base case flow rate value of 950 kg/h. As in Example 11, the split ratio was assumed to be 1:4, and the membrane area for the sweep-based membrane separation step was assumed to be 1600 m². The membrane areas for the two membrane-based capture steps, 326 and 328, were assumed to be 20 m² and 15 in², respectively. The results of the calculation are shown in Table 14.

TABLE 14 Stream Condenser Feed to CO2 CO2- C0 2- CO2- Air Gas to Coal O2 Overhead Capture vent rich lean Sweep Combustor Retentate Parameter (302) (301) (308) (309) (311) (312) (313) (301) (303) (214) Total Flow 55 50 1227 301 143 28 130 950 1492 712 (kg/h) Temp. (° C.) 25 25 30 40 38 36 36 25 29 25 Pressure 1.0 1.0 1.0 10.0 1.0 1.0 10.0 1.0 1.0 1.0 (bar) Component (vol %) Coal 100 0 0 0 0 0 0 0 0 0 (carbon + hydrogen) Oxygen 0 100 3.1 3.2 1.6 5.2 4.1 21.0 12.5 9.6 Nitrogen 0 0 57.1 59.2 15.7 58.7 92.9 79.0 57.1 86.5 Carbon 0 0 35.5 36.8 80.8 36.0 3.0 0 27.0 3.9 Dioxide Water 0 0 4.3 0.8 1.9 0.1 0 0 3.4 0

The feed gas, 309, to the two-step carbon dioxide capture process consists of 36.8 vol % carbon dioxide. The first carbon dioxide capture step, 326, yields a concentrated carbon dioxide product, 311, containing 80.8 vol % carbon dioxide. The feed stream, 310, from the first membrane unit, 326, is routed to second membrane unit, 328, to recover more of the carbon dioxide from the stream. The permeate stream, 312, from the second membrane unit, 328, contains 36,0 vol % carbon dioxide, which is then passed to the sweep-based membrane separation step, 330. The carbon-dioxide depleted feed stream, 313, from the second carbon dioxide capture step, 328, contains 3.0 vol % carbon dioxide. This stream is combined with the exhaust stream, 314, from the sweep-based membrane separation step, 330, and is routed to the environment with a carbon dioxide content of 3.9 vol %, The recovery of carbon dioxide is increased to 75% compared with 65% in Example 11.

These calculations show that a number of variants to the basic design of the process are possible. These changes to the process design and operating conditions will change the concentration of carbon dioxide in the stream sent to the carbon dioxide capture step and the overall recovery of carbon dioxide in the step. A trade-off exists between high carbon dioxide capture and high carbon dioxide concentration with the amount of membrane area in the sweep unit and other variable, such as the amount of compression used. The optimum conditions and design will depend on the goals of the plant operator and the cost of the membrane, compression, and so on.

Example 13 Turbine Process that Includes an Amine Absorption Step, But No Sweep-Based Membrane Separation Step (Not in Accordance with the Invention)

A flow diagram of a conventional turbine power generation process that includes an MEA-based amine absorption step, but no sweep-based membrane separation step, is shown in FIG. 10. According to this process, an incoming air stream 602 is compressed from atmospheric pressure to 20-30 bar in an air compressor unit 619. This compressed gas stream 603 is then combusted with the incoming fuel gas 601 (which is typically but not necessarily natural gas) in combustion unit, 604. The hot, high-pressure gas, 607, from the combustor is then expanded through the gas turbine 606. The low-pressure exhaust gas exhaust gas 605 from the gas turbine 606 is still hot, so that the energy content from this gas is recovered in a steam turbine, 612.

The exhaust gas, 613, from the steam turbine 612 is then passed to an MEA-based amine absorption step, 614, which produces a concentrated carbon dioxide product, 615. The carbon dioxide-depleted residue stream from the absorption process is exhausted to the environment as vent stream, 616. The results of the calculation are shown in Table 15.

TABLE 15 Stream Carbon Steam Turbine Dioxide Product Vent Stream Parameter Exhaust (613) Stream (615) (616) Total Flow (Mkg/h) 3.23 0.183 2.93 Temp. (° C.) 143 21 30 Pressure (bar) 1.0 1.6 1.0 Component (vol %) Oxygen 12.1 0 13.3 Nitrogen 74.3 0 81.9 Carbon Dioxide 4.0 98.9 0.5 Water 8.7 1.1 3.4

The amine absorption step 614 produces a product stream 615 containing approximately 99 vol % carbon dioxide and reduces the carbon dioxide of the vent stream 0.5 vol %, Total energy required is 81.5 MW.

Example 14 Turbine Process of the Invention

A flow diagram of a turbine power generation process of the invention that includes an MEA-based amine absorption step, and where a portion of the turbine exhaust stream and at least a portion of the off-gas from the absorption step are passed to a sweep-based membrane separation step is shown in FIG. 11. According to this process, an incoming air stream 702 is compressed from atmospheric pressure to 20-30 bar in an air compressor unit 719. This compressed gas stream 703 is then combusted with the incoming fuel gas 701 (which is typically but not necessarily natural gas) in combustion unit, 704. The hot, high-pressure gas, 707, from the combustor is then expanded through the gas turbine 706. The low-pressure exhaust gas exhaust gas 705 from the gas turbine 706 is still hot, so that the energy content from this gas is recovered in a steam turbine, 712.

A first portion, 722, of the exhaust gas, 713, from the steam turbine 712 is then passed to an MEA-based amine absorption step, 714, which produces a concentrated carbon dioxide product, 715. A second portion, 723, of the turbine exhaust gas 713 and the carbon dioxide-depleted residue stream, 716, from the absorption process 714 are combined and sent as a feed stream, 724, to a sweep-based membrane separation unit, 717, which contains membranes, 718, that are preferentially permeable to carbon dioxide over nitrogen, and to carbon dioxide over oxygen. Carbon dioxide:nitrogen selectivity was assumed to be 40; carbon dioxide:oxygen selectivity was assumed to be 20; and carbon dioxide permeance was assumed to be 5,000 gpu. The membrane area was assumed to be 1.8 million m².

Feed stream 724 passes across the feed side of membranes 718; a sweep stream, 719, of air passes across the permeate side at a pressure of 1 to 1.1 bar. A carbon dioxide-depleted residue stream, 721, is withdrawn from the feed side of the membranes. This stream has been reduced to 0.5 vol % carbon dioxide and can be vented directly to the environment.

Carbon dioxide-enriched sweep/permeate stream, 720, is withdrawn from the permeate side of the membrane and is sent with incoming air stream 702 to air compressor unit 719. The results of this calculation are shown in Table 16.

TABLE 16 Stream Steam CO₂ Turbine Amine Product Amine Sweep Permeate Vent Exhaust Feed Stream Residue Stream Stream Stream Parameter (713) (722) (715) (716) (719) (720) (721) Total Flow (Mkg/h) 3.06 1.34 0.183 1.16 2.8 3.14 2.54 Temp. (° C.) 25 25 25 25 36 36 36 Pressure (bar) 1.1 1.1 1.0 1.0 1.1 1.0 1.0 Component (vol %) Oxygen 7.8 7.8 0 8.6 20.9 15.9 12.9 Nitrogen 76.9 76.9 0 84.8 79.0 73.8 86.6 Carbon Dioxide 12.4 12.4 100 3.4 0.03 7.6 0.49 Water 2.9 2.9 0 3.2 0 2.7 0.08

The amine absorption step 714 produces a product stream 715 containing approximately 100 vol % carbon dioxide: the amine residue stream 716, containing approximately 3.4 vol % carbon dioxide, is sent as part of a feed stream the sweep-based membrane separation step 717.

Because of the membrane separation step, the amine plant treats 12.4 vol % carbon dioxide, and only has to strip the gas to 3.4 vol % carbon dioxide. This means that the volume of gas treated by the amine plant is only 35 million ft³/h, as opposed to 88 million ft³/h for a plant with no membrane contactor (as described in Example 13); as such, the absorber of the amine plant can be much smaller. Also, because he amine plant only has to go to 3.4 vol % carbon dioxide in the residue gas (stream 716), the stripper uses less energy. The amine plant plus membrane process uses 66 MW of energy −15 MW less energy than the amine plant alone. 

We claim:
 1. A process for controlling carbon dioxide exhaust from a combustion process, comprising: (a) performing a combustion process by combusting a mixture of a fuel and air, oxygen-enriched air, or oxygen, thereby creating an exhaust stream comprising carbon dioxide and nitrogen; (b) performing a carbon dioxide capture step to remove a portion of carbon dioxide in concentrated form from a first portion of the exhaust stream, thereby creating an off-gas stream from the capture step that is less concentrated in carbon dioxide than the exhaust stream; (c) providing a membrane having a feed side and a permeate side, and being selectively permeable to carbon dioxide over nitrogen and to carbon dioxide over oxygen; (d) passing a second portion of the exhaust stream and at least a portion of the capture step off-gas stream across the feed side; (e) passing air, oxygen-enriched air, or oxygen as a sweep stream across the permeate side; (f) withdrawing from the feed side a carbon-dioxide depleted vent stream; (g) withdrawing from the permeate side a permeate stream comprising oxygen and carbon dioxide; (h) passing the permeate stream to step (a) as at least part of the air, oxygen-enriched air, or oxygen used in step (a).
 2. The process of claim 1, wherein the at least a portion of the capture step off-gas stream that is passed to step (d) comprises between about 3 vol % to about 20 vol % carbon dioxide.
 3. The process of claim 1, wherein the exhaust stream emanates from a gas turbine.
 4. The process of claim 1, wherein the exhaust stream emanates from a steam turbine.
 5. The process of claim 1, wherein the exhaust stream comprises between about 10 vol % to about 25 vol % carbon dioxide.
 6. The process of claim 1, wherein the first portion of the exhaust stream that is sent to step (b) comprises between about 10 vol % and about '75 vol % of the total exhaust stream.
 7. cess of claim 6, wherein the first portion of the exhaust stream that is sent to step (b) comprises between about 20 vol % and about 65 vol % of the total exhaust stream.
 8. The process of claim 7, wherein the first portion of the exhaust stream that is sent to step (b) comprises between about 40 vol % and about 60 vol % of the exhaust stream.
 9. The process of claim 1, wherein the carbon dioxide capture step comprises at least one process selected from the group consisting of absorption, adsorption, liquefaction, and membrane separation.
 10. The process of claim 9, wherein the carbon dioxide capture step is an absorbent-based capture step.
 11. The process of claim 10, wherein the absorbent-based capture step comprises a chemical absorption process.
 12. The process of claim 11, wherein the chemical absorption process is an amine-based absorption process.
 13. The process of claim 11, wherein the chemical absorption process is a potassium carbonate scrubbing process.
 14. The process of claim 10, wherein the absorption-based carbon dioxide capture step comprises a physical absorption process.
 15. The process of claim 1, wherein the sweep stream follows a sweep flow direction across the permeate side, the off-gas stream follows a feed flow direction across the feed side, and the sweep flow direction is substantially countercurrent to the feed flow direction.
 16. The process of claim 1, wherein the membrane exhibits a carbon dioxide permeance of at least 500 gpu under process operating conditions.
 17. The process of claim 1, wherein the membrane exhibits a selectivity in favor of carbon dioxide over nitrogen of at least 10 under process operating conditions.
 18. The process of claim 1, wherein the vent stream comprises 3 vol % carbon dioxide or less. 